Thermal hydrocarbon recovery method with non-condensable gas injection

ABSTRACT

A method for recovering subsurface hydrocarbons, including heavy oil or bitumen, wherein a heated non-condensable gas such as nitrogen is injected downhole to heat the reservoir, followed by a steam injection step to heat the hydrocarbon to enable its flow to the wellbore and production to surface. The dual injection method can be repeated as desired to enhance production of the hydrocarbon resource, and in the case of cyclic steam stimulation would involve a period of shutting in the well after injection of the non-condensable gas and steam prior to the production phase.

FIELD OF THE INVENTION

The present invention relates to methods for hydrocarbon recovery from a subsurface reservoir, and specifically to recovery of heavy hydrocarbon deposits in fractured reservoirs.

BACKGROUND OF THE INVENTION

In the field of subsurface hydrocarbon production, it is known to employ various stimulation procedures and techniques to enhance production. For example, in the case of heavy oil and bitumen housed in subsurface reservoirs, conventional drive mechanisms may be inadequate to enable production to surface, and it is well known to therefore inject steam or steam-solvent mixtures to make the heavy hydrocarbon more amenable to movement within the reservoir permeability pathways, by heating the hydrocarbon and/or mixing it with lighter hydrocarbons or hot water.

Such heavy hydrocarbon deposits are sometimes located within naturally fractured reservoirs. Designing an optimal recovery method for extracting bitumen from such naturally fractured reservoirs can be tremendously challenging due to the structural complexity of the reservoirs. Generally speaking, in carbonate bitumen reservoirs, three different types of tectonic fractures have been noted: tension gashes, conjugate shears and extensional fractures. The tectonic fractures, with the exception of the short tension gashes, are dominantly sub-vertical and form an orthogonal system with parallel and/or perpendicular orientations. These fractures are usually consistent with the fractal-scale regional pattern that is due to basement reactivation as documented in the technical literature and as delineated with seismic ant-trackings.

Cyclic steam stimulation (CSS) is one of the most promising thermal recovery methods for producing high viscosity oil or bitumen from naturally fractured reservoirs. This oil recovery method requires a predetermined amount of steam to be injected into a well or wells drilled into the hydrocarbon deposit, which well or wells are then shut in to allow the steam and heat to soak into the reservoir surrounding the well and create what is known as a “steam chamber”. This assists the natural reservoir energy by thinning the oil (or, in the case of a steam-solvent injection, also mixing the heavy hydrocarbon with lighter hydrocarbons) so that it will more easily move through the fractures in the reservoir and into the production well or wells. Once the reservoir has been adequately heated and the steam chamber has been created, the production wells can be put back into production until the injected heat has been mostly dissipated within the fluids being produced and the surrounding reservoir rock and fluids. This cycle can then be repeated until the natural reservoir pressure has declined to a point that production is uneconomic, or until increased water production occurs.

While steam injection is one of the most promising thermal recovery methods for producing high viscosity oil, reservoir fracturing due to existing massive fracture networks presents a significant challenge for building a steam chamber in the reservoir. Steam that is intended to heat the reservoir and hydrocarbon can instead travel far from the source (injector well or wells) through the fracture system. Even steam that remains in the vicinity of the injector well(s) flows within the massive fracture systems and is subject to enoimous heat transfer and high heat losses, such that it condenses relatively quickly and loses most of its heat energy. In the result, the heat energy in the steam fails to impact the hydrocarbon deposit to enhance production.

SUMMARY OF THE INVENTION

The present invention is accordingly directed to heating the reservoir prior to steam injection. This heating stage employs a non-condensable gas.

Injecting heated non-condensable gas (NCG) prior to the steam injection (or along with steam) can be used to produce heavy oil or bitumen under viscosity reduction and gravity drainage methods, including from fractured carbonate reservoirs. In this novel method, heated NCG (for non-limiting example, nitrogen) is injected prior to or at the same time as steam injection, optionally in an otherwise typical CSS recovery method to heat the reservoir rock and fluid (primarily rock) and improve the efficiency of the injected steam, with less unwanted heat transfer/loss.

According to a first aspect of the present invention, then, there is provided a method for recovering a hydrocarbon from a reservoir, the method comprising the steps of:

a. drilling at least one well from surface to the reservoir; b. heating a volume of non-condensable gas to a target temperature; c. injecting the non-condensable gas down the at least one well to the reservoir; d. allowing the non-condensable gas to heat the reservoir and the hydrocarbon; e. injecting steam down the at least one well to the reservoir; f. allowing the steam to heat the reservoir and the hydrocarbon; and g. producing a portion of the hydrocarbon to the surface.

In some exemplary embodiments of the present invention, the hydrocarbon is preferably a heavy hydrocarbon, which heavy hydrocarbon may be heavy crude oil or bitumen. The reservoir may be composed primarily of carbonate material or non-carbonate clastic material, and it may include naturally occurring fractures. The at least one well may be a single well used for both injection and production, or it may comprise at least two wells, at least one of which is an injector well and at least one of which is a producer well. As indicated above, the non-condensable gas injection may occur before or concurrently with the steam injection.

The non-condensable gas is preferably selected from the group consisting of nitrogen, air, methane and carbon dioxide, and it may be injected through the same well as the steam or they may be injected through separate wells. While pure oxygen could be used as the NCG, it is not preferable due to the combustion and corrosion risk. The target temperature is preferably in the range of 100 to 400 degrees Celsius. In exemplary embodiments, steps b. through g. are to be repeated as desired.

According to a second aspect of the present invention, there is provided a method for recovering a hydrocarbon from a reservoir having at least one injector well therein, the method comprising the steps of:

-   a. injecting a heated non-condensable gas down the at least one     injector well to the reservoir; -   b. injecting steam down the at least one injector well to the     reservoir; -   c. producing a portion of the hydrocarbon to the surface; and -   d. repeating steps a. through c. as desired.

According to a third aspect of the present invention, there is provided a method for recovering a hydrocarbon from a reservoir, the method comprising the steps of:

-   a. drilling at least one well from surface to the reservoir; -   b. heating a volume of non-condensable gas to a target temperature; -   c. injecting the non-condensable gas down the at least one well to     the reservoir at a desired volume per unit time and for a desired     period of time; -   d. ceasing injecting of the non-condensable gas and allowing the     injected non-condensable gas to heat the reservoir and the     hydrocarbon; -   e. injecting steam down the at least one well to the reservoir; -   f. ceasing injection of the steam and allowing the steam to heat the     reservoir and the hydrocarbon; and -   g. producing a portion of the hydrocarbon to the surface.

In exemplary embodiments of the third aspect of the present invention, the target temperature is preferably in the range of 100 to 400 degrees Celsius, although target temperatures outside this preferred range may have utility in a given context, and the desired volume per unit time is preferably in the range of 20 to 100 mmcfd, although a useful desired volume per unit time may fall outside this range in a given context. The desired period of time is contextual and is directed to process optimization, which would be within the knowledge of the skilled person. Steps b. through g. can be repeated as desired.

According to a fourth aspect of the present invention, there is provided a method for building a steam chamber in a fractured subsurface hydrocarbon reservoir having at least one injector well therein, the method comprising the steps of:

-   a. heating a volume of non-condensable gas to a target temperature; -   b. injecting the non-condensable gas down the at least one injector     well to the reservoir; -   c. allowing the injected non-condensable gas to heat the reservoir     and hydrocarbon in the reservoir; -   d. injecting steam down the at least one injector well to the     reservoir; -   e. shutting in the at least one injector well and allowing the     injected steam to heat the reservoir and the hydrocarbon in the     reservoir; and -   f. producing a portion of the hydrocarbon to the surface.

In exemplary embodiments of the fourth aspect of the present invention, the method can additionally comprise the step after injecting the non-condensable gas of shutting in the at least one injector well, followed by opening the at least one injector well before injecting the steam.

A detailed description of an exemplary embodiment of the present invention is given in the following. It is to be understood, however, that the invention is not to be construed as being limited to this embodiment.

BRIEF DESCRIPTION OF THE DRAWINGS

In the accompanying drawings, which illustrate an exemplary embodiment of the present invention:

FIG. 1 is a flowchart illustrating an exemplary method according to the present invention;

FIG. 2 is a chart presenting numerical simulation test results comparing three different flow and temperature regimes compared to a standard CSS base case; and

FIG. 3 is a chart presenting numerical simulation test results comparing two different temperature regimes compared to a standard CSS base case, with nitrogen as the non-condensable gas.

An exemplary embodiment of the present invention will now be described with reference to the accompanying drawings.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENT

In the following detailed description, a specific application of the present invention is described, in particular an application for use with a CSS recovery method for bitumen housed in a fractured carbonate reservoir. However, it will be clear to those skilled in the art that other applications are possible within the scope of the present invention, including unique operating conditions and parameters specific to a particular reservoir context. That being the case, the following description is intended to be exemplary and non-limiting.

The present invention is intended for use with heavy hydrocarbons such as heavy oil and bitumen, although it can be used with lighter oils in appropriate circumstances that would be clear to one skilled in the art. Heavy and extra-heavy crude oils and bitumens are composed primarily of hydrocarbons, but they may also contain high molecular weight aliphatic and terpenoid hydrocarbons, asphaltenes, and oxygen-, nitrogen- and sulfur-bearing compounds. They occur naturally in porous and fractured reservoirs. Heavy oils and bitumens are commonly defined and characterized on the basis of both viscosity and density, and those skilled in the art will know of accepted viscosity and density ranges.

Turning to FIG. 1, an exemplary method 10 according to the present invention is illustrated. The method 10 begins with the step 12 of drilling a well into the reservoir to access the hydrocarbon deposit, which in the exemplary case is a bitumen housed in a massively fractured reservoir. Note that where the term “well” is used herein, it can mean either a vertical well or a horizontal well, and the term “wells” can mean vertical and/or horizontal wells or a combination of vertical and horizontal wells, as would be obvious to one skilled in the art. Once the well has been completed, a non-condensable gas is heated at step 14 and then injected down the well to the reservoir at step 16. The operator then continues the injection of the gas at a desired volume per unit time, for a desired period of time, allowing the non-condensable gas at step 18 to impart heat energy to the reservoir surrounding the wellbore. The well can optionally be shut in at this time, while the heat transfer continues. The specific volumes, time periods and even the heat level for the injected gas will depend in large part on the nature and structure of the reservoir, the type of hydrocarbon deposit being produced, and the availability of surface equipment. One skilled in the art will be able to select and operate available equipment to meet reasonable desired operating conditions for the method.

After the injected gas has imparted heat energy to the reservoir surrounding the wellbore, steam is then injected downhole to the reservoir at step 20. The skilled person will again know how to manage steam injection in a thermal hydrocarbon recovery operation. A mixture of steam and a selected solvent could also be used for this step, as is well known in the art. As the exemplary method is described in the context of a CSS operation, the next step 22 is shutting in the well. The injected steam is then allowed to heat the bitumen deposit at step 24. As is noted above, in prior art CSS methods, highly fractured carbonate reservoirs would sometimes drain away the steam or cause the heat energy to dissipate too quickly, making it a challenge to create the steam chamber necessary to enable hydrocarbon production at step 26. Due to injection of the non-condensable gas at step 16 and heating of the reservoir rock at step 18, the reservoir is already heated and the heat energy from the steam injection will accordingly not be as quickly dissipated. It is believed that this will enhance mobility of the heavy hydrocarbon material.

After the target hydrocarbon has been mobilized and produced, the cycle can be repeated at step 28. It is also possible to repeat the injection cycles one or more times before initial production.

Turning now to FIGS. 2 and 3, numerical simulation tests were conducted to assess the potential impact of the present invention when compared to a conventional CSS method. A series of dual-permeability flow simulation models were constructed based on the average geological properties from the Grosmont fractured carbonate formation. In this work STARS™ (advanced process and thermal reservoir simulator, version 2012) from Computer Modeling Group Ltd. was used to simulate and evaluate the process.

In the tests giving rise to the data presented in FIG. 2, simulations were run in which heated nitrogen gas at different volumes and temperatures was injected into the reservoir prior to the steam injection in each cycle, and the results were compared with the base case (CSS only). Note that in all cases, three full cycles are illustrated with increasing oil recovery factors. Each cycle begins with injection of NCG and steam, and then the plateau illustrates the elevated recovery level achieved by the dual injection method. In the base CSS case 30, a conventional CSS approach is used for a period over 300 days involving steam injection alone, shutting in and subsequent production, and the oil recovery factor (RF) was found to be only 1.4% in the simulation. In the first NCG case 32, nitrogen was heated to 400 degrees Celsius and injected at 20 mmcfd, with a result that the RF after three full cycles increased to 5.2%. This combination of a heated gas and a modest injection rate demonstrates a substantial potential improvement over CSS alone.

In the second NCG case 34, the gas is heated to a lower temperature, specifically 200 degrees Celsius, but injected at a higher rate of 100 mmcfd, with the result that the RF was increased to 9.5%. In the third NCG case 36, the gas was heated to 400 degrees Celsius and injected at a rate of 100 mmcfd, with the result that the RF was increased to 13.3%.

The results based on three simulated cycles illustrate that hydrocarbon recovery can be substantially increased by implementing the present invention by a factor of 3 to 9 compared to a conventional CSS recovery technique alone.

In the tests giving rise to the data presented in FIG. 3, simulations were run in which heated nitrogen gas was injected into the reservoir prior to the steam injection in each cycle, and the results were compared with the base case (CSS only). Note that in all cases, three full cycles are illustrated with increasing oil recovery factors. Each cycle begins with injection of NCG and steam, and then the plateau illustrates the elevated recovery level achieved by the dual injection method. Unlike the test results shown in FIG. 2, the test results shown in FIG. 3 are the result of NCG temperature modification alone, without reference to injection rate as the injection rate was the same for each run. In the base CSS case 40, a conventional CSS approach is used for a period over 300 days involving steam injection alone, shutting in and subsequent production, and the RF was found to be only 1.4% in the simulation. In the first NCG case 42, nitrogen was heated to 200 degrees Celsius, with a result that the RF after three full cycles increased to 9.5%. In the second NCG case 44, nitrogen was heated to 400 degrees Celsius, with a result that the RF after three full cycles increased to 13.3%. The preliminary results of three cycles illustrate that hydrocarbon recovery may be increased by a factor of 6 to 9 compared to a conventional CSS recovery technique alone.

The foregoing is considered as illustrative only of the principles of the invention. The scope of the claims should not be limited by the exemplary embodiment set forth in the foregoing, but should be given the broadest interpretation consistent with the specification as a whole. 

1. A method for recovering a hydrocarbon from a reservoir, the method comprising the steps of: a. drilling at least one well from surface to the reservoir; b. heating a volume of non-condensable gas to a target temperature; c. injecting the non-condensable gas down the at least one well to the reservoir; d. allowing the non-condensable gas to heat the reservoir and the hydrocarbon; e. injecting steam down the at least one well to the reservoir; f. allowing the steam to heat the reservoir and the hydrocarbon; and g. producing a portion of the hydrocarbon to the surface.
 2. The method of claim 1 wherein the hydrocarbon is a heavy hydrocarbon.
 3. The method of claim 2 wherein the heavy hydrocarbon is heavy crude oil or bitumen.
 4. The method of claim 1 wherein the reservoir is composed primarily of carbonate material.
 5. The method of claim 1 wherein the reservoir is composed primarily of non-carbonate clastic material.
 6. The method of claim 1 wherein the reservoir includes fractures.
 7. The method of claim 6 wherein the fractures are naturally occurring.
 8. The method of claim 1 wherein the at least one well is a single well used for both injection and production.
 9. The method of claim 1 wherein the at least one well is at least two wells, at least one of which is an injector well and at least one of which is a producer well.
 10. The method of claim 1 wherein the non-condensable gas is selected from the group consisting of nitrogen, air, methane and carbon dioxide.
 11. The method of claim 1 wherein the target temperature is in the range of 100 to 400 degrees Celsius.
 12. The method of claim 1 wherein the non-condensable gas and the steam are injected through separate wells.
 13. The method of claim 1 further comprising repeating steps b. through g. as desired.
 14. A method for recovering a hydrocarbon from a reservoir having at least one injector well therein, the method comprising the steps of: a. injecting a heated non-condensable gas down the at least one injector well to the reservoir; b. injecting steam down the at least one injector well to the reservoir; c. producing a portion of the hydrocarbon to the surface; and d. repeating steps a. through c. as desired.
 15. The method of claim 14 wherein the hydrocarbon is a heavy hydrocarbon.
 16. The method of claim 15 wherein the heavy hydrocarbon is heavy crude oil or bitumen.
 17. The method of claim 14 wherein the reservoir is composed primarily of carbonate material.
 18. The method of claim 14 wherein the reservoir is composed primarily of non-carbonate clastic material.
 19. The method of claim 14 wherein the reservoir includes fractures.
 20. The method of claim 19 wherein the fractures are naturally occurring.
 21. The method of claim 14 wherein the at least one injector well is a single well used for both injection and production.
 22. The method of claim 14 wherein the at least one injector well is at least two injector wells, at least one of which is also configured for use as a producer well.
 23. The method of claim 14 wherein the non-condensable gas is selected from the group consisting of nitrogen, air, methane and carbon dioxide.
 24. A method for recovering a hydrocarbon from a reservoir, the method comprising the steps of: a. drilling at least one well from surface to the reservoir; b. heating a volume of non-condensable gas to a target temperature; c. injecting the non-condensable gas down the at least one well to the reservoir at a desired volume per unit time and for a desired period of time; d. ceasing injecting of the non-condensable gas and allowing the injected non-condensable gas to heat the reservoir and the hydrocarbon; e. injecting steam down the at least one well to the reservoir; f. ceasing injection of the steam and allowing the steam to heat the reservoir and the hydrocarbon; and g. producing a portion of the hydrocarbon to the surface.
 25. The method of claim 24 wherein the hydrocarbon is a heavy hydrocarbon.
 26. The method of claim 25 wherein the heavy hydrocarbon is heavy crude oil or bitumen.
 27. The method of claim 24 wherein the reservoir is composed primarily of carbonate material.
 28. The method of claim 24 wherein the reservoir is composed primarily of non-carbonate clastic material.
 29. The method of claim 24 wherein the reservoir includes fractures.
 30. The method of claim 29 wherein the fractures are naturally occurring.
 31. The method of claim 24 wherein the at least one well is a single well used for both injection and production.
 32. The method of claim 24 wherein the at least one well is at least two wells, at least one of which is an injector well and at least one of which is a producer well.
 33. The method of claim 24 wherein the non-condensable gas is selected from the group consisting of nitrogen, air, methane and carbon dioxide.
 34. The method of claim 24 wherein the target temperature is in the range of 100 to 400 degrees Celsius.
 35. The method of claim 24 wherein the non-condensable gas and the steam are injected through separate wells.
 36. The method of claim 24 wherein the desired volume per unit time for the non-condensable gas injection is in the range of 20 to 100 mmcfd.
 37. The method of claim 24 further comprising repeating steps b. through g. as desired.
 38. A method for building a steam chamber in a fractured subsurface hydrocarbon reservoir having at least one injector well therein, the method comprising the steps of: a. heating a volume of non-condensable gas to a target temperature; b. injecting the non-condensable gas down the at least one injector well to the reservoir; c. allowing the injected non-condensable gas to heat the reservoir and hydrocarbon in the reservoir; d. injecting steam down the at least one injector well to the reservoir; e. shutting in the at least one injector well and allowing the injected steam to heat the reservoir and the hydrocarbon in the reservoir; and f. producing a portion of the hydrocarbon to the surface.
 39. The method of claim 38 comprising the further steps of shutting in the at least one injector well after injecting the non-condensable gas, and subsequently opening the at least one injector well before injecting the steam.
 40. The method of claim 38 wherein the hydrocarbon is a heavy hydrocarbon.
 41. The method of claim 40 wherein the heavy hydrocarbon is heavy crude oil or bitumen.
 42. The method of claim 38 wherein the reservoir is composed primarily of carbonate material.
 43. The method of claim 38 wherein the reservoir is composed primarily of non-carbonate clastic material.
 44. The method of claim 38 wherein fractures in the reservoir are naturally occurring.
 45. The method of claim 38 wherein the at least one injector well is a single well used for both injection and production.
 46. The method of claim 38 wherein the at least one injector well is at least two injector wells, at least one of which is also configured for use as a producer well.
 47. The method of claim 38 wherein the non-condensable gas is selected from the group consisting of nitrogen, air, methane and carbon dioxide.
 48. The method of claim 38 wherein the target temperature is in the range of 100 to 400 degrees Celsius.
 49. The method of claim 38 wherein the non-condensable gas and the steam are injected through separate wells.
 50. The method of claim 38 further comprising repeating steps a. through f. as desired. 